UNDERGROUND FORMATION

BACKGROUND OF THE INVENTION

The invention relates to a method and system for controlling water flux through an underground

formation .

Such a method and system are known from SPE paper

120460 entitled "Measurements of streaming potential for downhole monitoring in intelligent wells" presented by M.Z.Jaafar, J.Vinogradov, M.D.Jackson, J.H.Saunders and C.C.Pain of Imperial College, London at the 2009 SPE Middle East Oil & Gas Show and Conference held in the Bahrain International Exhibition Centre, Kingdom of Bahrain, 15-18 March 2009.

This SPE paper discloses that downhole monitoring of Streaming Potential (SP) , using electrodes on the outside of an insulated casing, is a promising new technique for monitoring water encroachment towards a well and that water encroaching on a well could be monitored while it is several tenths to hundreds of meters away from the well.

Other methods for measuring Streaming Potential (SP) in underground formations are known from European patent application 0043768 and from US patent

applications US2004/0069487, US2008/0159073 and

US2008/0159073.

These patent applications disclose that SP

measurements can be used for permeability logging, SP measurement in a non-producing micro-borehole, using SP generated by a pressure difference to determine

wettability of an earth formation, and/or use of SP to locate fractures, to measure formation permeability, to estimate formation pressure, to monitor drilling fluid loss and/or to detect abnormal pressure.

It is furthermore known in the art that intelligent oil and/or gas production wells with fluid flow

monitoring and fluid flow control methods improve oil and gas recovery and suppress water production.

The current methods of inflow regulation into intelligent wells fall broadly into two groups:

1) those where the inflow restrictions are committed to at surface when the well completion is deployed (e.g. with selectable flow area Inflow Control Devices

(ICDs) ) ; and

2) those where a number of Inflow Control Valves (ICVs) are installed in the well where the aperture of the inflow valve can be modulated from surface.

The purpose of both intelligent well inflow control groups 1) and 2) is to allow adjustment of inflow rate from different zones of the oil- or gas-bearing

reservoir formation. If this control is achieved correctly, the inflow profile along the wellbore is managed such that the encroaching water reaches the well evenly and at the same time. Delaying the

breakthrough of water generally increases the sweep efficiency so more oil or gas is produced, and reduces the operational difficulties surrounding the treatment and disposal of formation water.

The first intelligent well inflow control group of inflow regulation utilising fixed ICDs is often the least expensive and can exhibit excellent performance. However, the settings are based on model predictions following the results of logging and testing of the well during and after drilling. The method is

therefore open loop and susceptible to unrecognised and/or uncharacterised geological features in the reservoir, hydrocarbon fluids, supporting aquifers or water injection strategies. This often results in the performance of such ICD-based completions falling short of predictions.

The second intelligent well inflow control group of inflow control improves on the first method in that the regulating behaviour of the ICV can be altered during the life of the well. However, it is currently the case that alterations to the ICV positions are generally based either on model predictions, so the method remains susceptible to unrecognised and/or

uncharacterised geological features in the reservoir, hydrocarbon fluids, supporting aquifers and water injection strategies, or are a reactive response to measurements of water or sand in produced fluids.

US patent 7,063,162 discloses an example of the second intelligent well inflow control method wherein a single ICV is used to migrate the level of maximum influx along an elongate inflow region of a hydrocarbon fluid production well.

US patent 7,672,825 discloses an intelligent well inflow control algorithm which adjusts ICV settings to proactively regulate inflow to an intelligent well or well cluster such that water evenly encroaches the inflow sections of the well or well cluster.

In many reservoirs, water encroaches on the

production wells as hydrocarbons are extracted. This water may move into the reservoir from an underlying or adjoining aquifer, or be injected via wells as water or steam. During production from gas-brine reservoirs, or thin oil rim reservoirs with aquifer support, or waterflooded oil reservoirs, or steam-assisted gravity drainage, or other reservoir types in which early water breakthrough is a risk, proactive inflow control requires the detection of changes in water saturation in the reservoir at a distance from the production well as fluids are produced. The dynamic and time varying changes in water saturation can then be used to control the settings of the ICVs installed in the well and thus balance inflow to delay water breakthrough and improve sweep efficiency. The key effects that cause early water breakthrough include uneven drawdown pressure into the wellbore (e.g. cresting at the heel of a horizontal well), permeability heterogeneity caused by geologic heterogeneity in the formation, fracture flow and coning or cresting of the waterfront in low

permeability reservoirs produced at high rate.

There are a number of methods currently available for monitoring changes in saturation within a reservoir during oil or gas production, including the use of so- called 4D seismic methods, Controlled Source

Electromagnetic (CSEM) surveys and resistivity logging using permanently installed downhole electrodes. None of these methods are widely used at present. 4D seismic exhibits low temporal resolution, with repeat surveys conducted at (typically) greater than yearly intervals, which is not frequent enough to make inflow control decisions. Moreover, both seismic and CSEM exhibit low spatial resolution, especially in the vertical plane (5 - 10m grid blocks for seismic, ~100m grid blocks for CSEM) .

The permanent resistivity logging method, which is typically deployed with the lower completion or liner and is described in by Bryant et al in SPE paper 71710 published by the Society of Petroleum Engineers, exhibits relatively low penetration depths from the well into the reservoir. It is expected that pro-active control is improved in many production scenarios with increasing depth of detection of saturation changes in the reservoir. Greater sensing range away from the wellbore increases wellbore inflow control performance because the encroaching water is further away from the well, so control actions have more time to take effect.

There is a need for an improved method for

controlling a of water through a formation towards a hydrocarbon fluid production or other well, wherein a Streaming Potential (SP) is used not only to monitor water encroaching on a well while it is several tenths to hundreds of meters away from the well, but also to thereby effectively inhibit and/or delay influx of water into the well.

There is also a need for an improved method for inhibiting influx of water into a hydrocarbon fluid production well which method is able to keep a

waterfront approaching an elongate inflow region of the well at a substantially uniform distance from that inflow region.

SUMMARY OF THE INVENTION

In accordance with the invention there is provided a method for measuring a Streaming Potential (SP) to monitor water encroachment through an underground formation towards a hydrocarbon fluid production well

- characterized in that the method is used to generate a substantially uniform migration of a waterfront through the formation towards the inflow region of the well by:

- providing the inflow region of the well with a plurality of longitudinally spaced fluid inflow sections, which each comprises a Streaming

Potential (SP) sensor and an associated fluid Inflow

Control Device ( ICD) ; and

- inducing at least one Streaming Potential (SP) sensor to change an aperture of the associated Inflow Control

Device (ICD) in response to a difference between the

Streaming Potential (SP) measured by the SP sensor from the Streaming Potential (SP) measured by at least one other SP sensor.

It will be understood that each Inflow Control

Device (ICD) may be an Inflow Control Valve (ICV), a downhole pump and/or compressor, an adjustable smart sandscreen, and/or a swellable aperture that gradually opens or closes an inflow aperture or other opening through which hydrocarbon fluid, such as crude oil and/or natural gas flows from the formation into a particular inflow section where a particular SP sensor is installed. The range of SP sensors installed at the range of inflow sections spanning the length of the inflow region will thereby automatically generate a substantially uniform approach of a waterfront towards the entire inflow region, even if the waterfront is located at a distance of tenths or hundreds of meters away from the inflow region.

Optionally the method is used to create a

substantially uniform migration of a waterfront through the formation to each of the inflow sections of the segmented inflow region of the well by inducing a control algorithm to compare the streaming potentials measured by the streaming potential sensors with each other and to control the apertures of each of the associated inflow control devices such that differences between the

streaming potentials measured by the various streaming potential sensors are minimized, wherein the control algorithm may be a closed loop algorithm that

automatically controls the apertures of each of the inflow control valves to create a substantially uniform approach of a waterfront to each of the inflow sections and thereby postpone inflow of water into the hydrocarbon fluid production well without taking into account

predictions of a reservoir model and/or requiring

interpretation of the streaming potential measurements by an operator of the well.

Optionally, the control algorithm of at least one assembly of a streaming potential sensor and associated inflow control valve controls the opening of the

associated inflow control valve as a functional feedback loop between normalized streaming potential measured by the sensor and the settings of the associated inflow control valve.

The method according to the invention may be used to enhance production of hydrocarbon fluid, such as crude oil and/or natural gas, through the well and/or to monitor the approach of a waterfront through the oil containing formation and to assess a distance of the waterfront from at least one streaming potential sensor in at least one inflow section of the well.

In accordance with the invention there is furthermore provided a system for controlling water flux through an underground formation, comprising:

- a plurality of Streaming Potential (SP) sensors for measuring the Streaming Potential (SP) at various locations along the length of a fluid inflow region of the well; and

- at least one Inflow Control Valve (ICV) for controlling the level of inflow of fluids along the length of the inflow region of the well;

characterized in that the well comprises a segmented inflow region with a plurality of longitudinally spaced fluid inflow sections which each comprise an assembly of a fluid inflow control valve and an associated Streaming

Potential (SP) sensor, wherein each Streaming

Potential (SP) sensor changes an aperture of the

associated Inflow Control Device (ICD) in response to variation of the streaming potential measured by the sensor and wherein at least one fluid inflow section comprises an annular inflow zone surrounding a central production tubing and the fluid inflow valve is a valve arranged between the annular inflow zone and the central production tubing and the associated Streaming

Potential (SP) sensor is arranged in the annular inflow zone .

The Streaming Potential (SP) sensor may be a silver- silver chloride electrode mounted at the outer surface of a metallic sandscreen arranged in an annular inflow zone or of a impermeable metallic liner section, which outer surface is coated with an electric insulation material, which may comprise mill varnish.

In summary, the method and system according to the present invention use measurements of Streaming

Potential (SP) , acquired using electrodes permanently installed downhole, to detect changes in water saturation at a distance from the well. The measurements may be used in a feedback loop to directly actuate one or more Inflow Control Devices ( ICDs ) installed downhole. This improves oil and gas recovery and delays water production by controlling inflow such that the encroaching water reaches the well evenly and at the same time. These and other features, embodiments and advantages of the method and system according to the invention are described in the accompanying claims, abstract and the following brief and detailed descriptions of non-limiting embodiments depicted in the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

Figures la and lb show how in pores of an underground formation streaming currents and streaming potentials are generated by moving ions;

Figures 2a and 2b show a vertical cross-sections through a reservoir model showing the water saturation as water (white) encroaches on a vertical (black) oil

production well at (a) 231 days and (b) 463 days;

Figure 2c shows the streaming potential versus distance from the production well at four different time steps, including those illustrated in Fig2a and 2b;

Fig.3 shows the streaming potential measured along the length of the well shown in Fig.2;

Fig.4 shows a vertical cross-section through a reservoir model showing the streaming potential (in volts) throughout the reservoir layer with the position of the waterfront marked by a solid black line;

Figure 5 shows example relationships between inflow rate and normalized average streaming potential using equation 3; and

Figure 6 shows the relative streaming potential coupling coefficient as a function of water saturation during drainage and imbibitions, measured in sandstone core plugs saturated with oil and water.

DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENTS

Figure 1 (a) shows how the mineral surfaces in

reservoir rocks become negatively charged at typical reservoir conditions, leading to the formation of an electrical double layer at the solid-fluid interfaces.

Figure 1 (b) shows that when the fluid is induced to flow, some of the excess counter-ions within the double layer are transported with the flow, giving rise to an electrical current termed the streaming current. At steady state, the streaming current is countered by a conduction current. Associated with this conduction current is an electrical potential termed the streaming potential.

Streaming potentials in fluid saturated porous media are one of the phenomena included under the term

spontaneous potential. They result from the presence of an electrical double layer at the solid-fluid interface, as is illustrated in Figures la and lb. The solid

surfaces become electrically charged when they react with the adjacent fluid; at typical reservoir conditions, the mineral surfaces in hydrocarbon reservoir rocks are negatively charged. Electrostatic forces attract counter- ions in the fluid which have the opposite charge to the surface, and repel co-ions which have the same charge as the surface. This gives rise to a boundary layer

adjacent to the mineral surface, which contains an excess of counter-ions. Within this boundary layer, the

concentration of excess counter-ions decreases away from the solid surface until the fluid becomes electrically neutral. The thickness of the boundary layer is typically tens of nanometers.

If the fluid is induced to flow relative to the solid surfaces by an external potential (pressure) gradient, then some of the excess counter-ions within the boundary layer are transported with the flow, giving rise to an electrical current termed the streaming current, as illustrated in Fig. lb. At steady state, the streaming current is countered by a conduction current through the fluid (and rock, if it is conductive) to maintain overall electrical neutrality. Associated with this conduction current is an electrical potential termed the streaming potential (SP) . Downhole measurements of the SP, which is generated when water flows in the reservoir during production, provides information on the water saturation at some distance from the well.

As oil or gas is extracted from a hydrocarbon fluid production well, the encroaching waterfront moves toward the well. The magnitude of the SP peaks at the location of the waterfront and decays toward zero (measured with respect to a distant reference electrode) ahead of and behind the front as illustrated in Figure 2.

Figures 2a and 2b are a schematic vertical cross- sections through a three dimensional (3D) reservoir model showing the water saturation in Figure 2a at (a) 231 days and in Figure 2b at (b) 463 days as water (white) encroaches on a vertical oil (black) production well located at 0 m on the horizontal axis. Figure 2c shows the streaming potential versus distance from the

production well along a one dimensional (ID) horizontal profile through the centre of the model shown in Figures 2a and 2b, at four different time steps. The peak of the potential curve is located at the position of the

advancing waterfront, but the envelope of the curve encompasses the production well when the front is several tens to hundreds of metres away. This is why streaming potential measurements can detect advancing waterfronts while they are still some distance from the well.

Figure 2c shows that the SP falls to zero ahead of the front because there is no streaming current associated with the flow of oil or gas; it falls to zero behind the front because the streaming current is

constant where the water saturation is constant. The peak in magnitude of the SP follows the waterfront as it moves through the reservoir, and is associated with the front because the divergence of the streaming current becomes nonzero where the saturation changes, so the waterfront acts as a current source.

Measurements of SP can therefore be used to monitor water encroaching on an oil or gas production well because the peak in magnitude of the SP is associated with the waterfront. Moreover, a waterfront approaching a production well can be monitored before it arrives, because the magnitude of the SP signal decays slowly with distance away from the location of the front. As soon as the leading edge of the SP signal caused by the moving front arrives at the well, a change in potential is recorded that can be used in a feedback loop to control inflow to the well, as illustrated in Figure 3.

Figure 3 shows Streaming potential measured along the length of the hydrocarbon fluid production well shown in Figure 2. The legend shows the distance of the waterfront from the well. As the waterfront approaches, the

streaming potential increases at the well, with the peak of the potential located at the centre of the reservoir layer .

This increase is caused by the approaching waterfront as shown in Figure 2.

Figure 3 furthermore shows that the magnitude of the potential measured at the well increases as the distance to the waterfront decreases, because the peak of the electrical signal associated with the front moves closer. At water breakthrough, the peak signal arrives at the well .

The value of SP measured at the well reflects the distance of the waterfront from the well. The higher the magnitude of the measured SP, the closer the waterfront.

Therefore variations in the magnitude of the measured SP along the wellbore are indicative of uneven encroachment of water on the wellbore as is illustrated in Figures 4 a-d .

Figures 4 a-d each show a vertical cross-section through a 3D reservoir model showing the streaming potential (in volts) throughout the reservoir layer, with the position of the waterfront marked by a solid black line .

Figures 4 a and c show potentials for a homogeneous model with the water front at 300 and 100 m from the well, respectively.

Figures 4b and d show potentials from the model with high permeability in the lower part of the reservoir with the water front at 300 and 100 m from the well,

respectively. The maximum streaming potential signal shifts to reflect the uneven nature of the encroaching waterfront .

Figures 4a-d show that controlling inflow to the well in such a way that the variation of the measured SP along the wellbore is minimised, induces the encroaching waterfront to reach the well evenly and at the same time. This may achieved in accordance with an embodiment according to the present invention by subdividing the production well into a number of inflow zones, each of which has an Inflow Control Valve ICV installed, of which the settings of which can be adjusted by a control algorithm connected to a Streaming Potential (SP) sensor arranged in the relevant well inflow zone. The number of zones is identified using model predictions in

conjunction with economic and technical factors.

Increasing the number of ICVs allows control of the encroaching waterfront with higher spatial resolution.

The magnitude of the measured SP at the well is proportional to the local pressure drawdown and related to the distance from the wellbore to the water.

Variations in the magnitude of the SP signal, normalised to those measured when the well is initially produced, reflect variations in the distance to the waterfront, with larger normalised signals corresponding to flowing water which is closer.

In order to measure the SP a number of Streaming Potential (SP) sensors provided by SP sensing electrodes need to be installed on the well and placed in contact with the reservoir. These electrodes can take a variety of physical forms, be made using a variety of metals but it is preferred that the design is simple to install and robust in operation. Electrode designs are well

understood and are available over a range of temperature ratings and physical sizes. Bare metal electrodes

typically perform not very well, especially in free fluid where convective shearing of charge over the surface causes fluctuations in electrode potential. Buffered designs, where an electrode is held in a strong saline gel buffer fluid and connected to the measurement media through a porous plug perform much better. Silver/Silver Chloride electrodes work well up to temperatures of around 90°C and only have minor inaccuracies at higher temperatures .

The electrodes are to be arranged correctly downhole. There is no minimum electrode spacing but practical considerations will mean that one electrode per casing or other well tubular joint will be the shortest spacing. The electrodes will be clamped and protected using conventional methods.

It is relevant to consider electrical insulation of the casing. There are a number of electrical insulation methods which are availabe at present, including the use of non-metallic casings constructed out of glass fibre composites, or GRP (Glass reinforced plastics) liners or outer claddings. While this approach offers a good solution a requirement such as this will not always meet the performance specification for the well construction. In the system according to the invention the casing insulation is preferably provided by a thick coat of mill varnish which is normally applied during manufacture to protect the metallic casing or other well tubular

sections from corrosion prior to deployment. The

formulation and application method is unchanged here to around 0.5mm. While the insulation is imperfect in this case (e.g. at perforations or thread connections) approximately 95% or more of the surface of the metallic casing or other well tubular is insulated. The streaming potential generation mechanism and electrode system is sufficiently tolerant so as not to be significantly adversely affected.

In the method and system according to the invention an Inflow Control Valve (ICV) aperture control algorithm may be used, which uses a functional feedback loop between normalised SP measured downhole, and the settings of the Inflow Control Valves (ICVs) . For inflow control purposes, the well is subdivided into a number of zones, each of which is equipped with an ICV, and a number of electrodes, which depends upon the length of the zone and the spacing of the electrodes. The number of zones is chosen based on the predictions of well and reservoir models .

The control algorithms may be subdivided into three steps 1,2 and 3, which are described in more detail in paragraphs 1-3 below.

The first and second steps are common to all

algorithms. The first step is implemented when the well is first completed and tested. The second and third steps are implemented each time a control action is taken.

The third step differs in detail depending upon the type of ICVs installed in each zone of the well and four options of step 3 are described in more detail in

sections 3.1-3.4.

Step 1: Establish the baseline streaming potential

After completion of the well, including the installation of the electrodes, the well is opened for production and tested until both a steady flow at the surface, and a steady suite of electrical potentials measured downhole, is obtained. Measurements of electrical potential in the reservoir are made with reference to one or more

electrodes installed at a shallower level, above the mudstone seal. At this stage, poorly performing

electrodes (e.g. those which fail to provide a steady signal, or are noisy, or which provide no signal) are identified and eliminated from the control loop. The potential measurements obtained during testing are used to establish the baseline potential at each electrode.

Step 2: Obtain the normalized average streaming potential magnitude for each zone during production

During production, the SP at each electrode is filtered and digitized at a frequency of a few Hz. The arithmetic average SP for each zone, normalized to the baseline potential, is calculated from the magnitude of the electrode measurements obtained in that zone, and over the control time interval, using

equation (1)

where V _za is the average normalized (dimensionless ) potential of zone z, n is the number of electrodes in zone z, V _Z i is the potential of electrode i in zone z, V _z i is the baseline potential of electrode i in zone z, t is the control time interval, and m is the number of measurements from each electrode over the control time interval. The normalized average zonal SP V _za is lowest for the zone in which the waterfront is furthest away, and highest for the zone in which the waterfront is closest. This information is used in the feedback control algorithm to adjust the settings of the ICVs, controlling inflow such that the encroaching water reaches the well evenly and at the same time.

Step 3: Determine and apply the ICV settings for each zone .

The inflow control policy is designed to ensure that one ICV is fully open at all times, to maximize the total production rate. Closing all of the ICVs is equivalent to choking the well at surface. The way in which the other ICVs are controlled, depends upon the type and number of ICVs installed in the well. For meaningful control, at least two ICVs must be installed, yielding two separately controllable zones. ICVs may be simple on/off valves, or may have multiple settings or be continually adjustable.

Step 3.1: Two ICVs of on/off type The ICV controlling flow from the zone (z) with the minimum average SP (V _m i _na ) is kept open and the ICV controlling flow into the other zone is closed. In the shut-in zone, the SP signal may decrease as the water moves more slowly, or stops moving, towards the

completion. If this occurs, both ICVs are opened and a short test is conducted (likely for a few hours until stable flow and potential readings are obtained) to investigate the behaviour of the SP in each zone, before implementing a new control action using the rules described above. The time interval between control actions will depend upon the local operator. A higher frequency of control actions will yield more precise regulation of the encroaching waterfront.

If shutting-in production from the zone with the highest value of average SP causes the total production rate and/or bottom-hole pressure (BHP) to fall below a target limit, then inflow from this zone is restricted by closing the ICV until the production constraints until the production constraint is violated, then opening the

ICV until the next operator-specified control action. However, it should be recognised that this may lead to earlier water breakthrough.

Step 3.2: Multiple ICVs of on/off type.

The ICV controlling flow from the zone (z) with the minimum average SP (V _m i _na ) is kept open and the ICV controlling flow into the zone with the maximum average SP {V _maxa ) is closed. Zones with intermediate values of normalized SP are kept open or closed depending upon whether the normalized zonal average potential, scaled between the maximum and minimum value V _7m = ^{Vza Vmina} equation (2]

Vmaxa -Vmi.na exceeds a threshold value. The scaled zonal average potential varies between 0 and 1, where 0 is the value in the zone where the water is furthest away, and 1 is the value in the zone where the water is closest. A default value for this threshold is therefore 0.5. If a bespoke value is required then one or more reservoir simulation models, which can also generate predictions of the SP signal, can be used to identify a different threshold for a specific well in a particular reservoir. Any number of optimisation algorithms can be used for this purpose. In shut-in zones, the SP signal may decrease as the water moves more slowly, or stops moving, towards the

completion. If this occurs, then the ICV is opened again once the normalized potential falls below the specified threshold, following the rules described above. Likewise, the SP signal in a zone which was previously open may exceed the threshold, in which case the zone is shut-in. The time interval between control actions will depend upon the local operator. A higher frequency of control actions will yield more precise regulation of the

encroaching waterfront.

If shutting-in production from multiple zones causes the total production rate and/or BHP to fall below a target limit, then the threshold value of normalized zonal average potential is increased until enough zones are producing to avoid violating the global production constraints. However, it should be recognised that this may lead to earlier water breakthrough.

Step 3.3: Two ICVs of multiple settings/continually adjustable type. The ICV controlling flow from the zone (z) with the minimum average SP (V _m i _na ) is kept open. The ICV

controlling flow into the other zone is partially or wholly closed so as to minimize the variation in

normalized zonal average SP between the zones. The ICV setting is identified in a trial-and-error process whilst monitoring the normalized zonal average SP in each zone. The time interval between control actions will depend upon the local operator. A higher frequency of control actions will yield more precise regulation of the

encroaching waterfront.

If shutting-in production from the zone with the highest value of average SP causes the total production rate and/or bottom-hole pressure (BHP) to fall below a target limit, then production from this zone is

restricted but without violating the global production constraints. This may lead to earlier water breakthrough.

Step 3.4: Multiple ICVs of multiple

settings/continually adjustable type.

The ICV controlling flow from the zone (z) with the minimum average SP (V _m i _na ) is kept open and the ICV controlling flow into the zone with the maximum average SP {V _maxa ) is closed. Zones with intermediate values of normalized SP are partially closed depending upon the value of the normalized zonal average potential, scaled between the maximum and minimum value (equation 2) . To implement this control action, a functional relationship between the setting of the ICV and the scaled zonal average potential is used of the form equation (3) where q _zp is the inflow rate from zone z when the ICV is partially closed, q _zo is the inflow rate from zone z when the ICV is open, and A, B and C are constants. The relationship between ICV setting and inflow rate for a given pressure gradient must be determined or provided by the vendor for the ICV in use.

The values of the constants A, B and C for a specific well in a particular reservoir are identified by the operator based on the predictions of one or more

reservoir simulation models, which can also generate predictions of the SP signal. Any number of optimisation algorithms can be used for this purpose. In the absence of such a model, default values of the constants would be A=0, B=l and C=l, in which case the inflow rate decreases linearly with increasing scaled zonal average potential

{V _zsa ) as illustrated in Figure 5.

Figure 5 shows example relationships between inflow rate and normalized average potential obtained using equation 3 with:

(A) A = 0, B = 1 and C = 1 (linear variation between inflow and potential);

(B) A = 0, B = 1 and C = 0.5 (inflow decreases less rapidly as potential increases);

(C) A = 0, B = 1 and C = 2 (inflow decreases more rapidly as potential increases);

(D) A = 0.5, B = 0.5 and C = 5 (ICV remains partially open even when normalized potential is a maximum) ;

(E) A = 0 , B = 2 and C = 1 (ICV remains fully open until normalized potential exceed a threshold value) .

Many other inflow control relationshops are possible depending upon how the constants A, B and C are chosen.

In shut-in zones, or zones where inflow has been restricted, the SP signal may decrease as the water moves more slowly, or stops moving, towards the completion. This will be reflected by the ICVs in these zones partially or fully opening. Moreover, the zones with the maximum and minimum values of average normalized SP may switch. The control algorithm adjusts inflow accordingly to reflect the time-varying nature of the signal. The time interval between control actions will depend upon the local operator.

A higher frequency of control actions will yield more precise regulation of the encroaching waterfront. If restricting production from multiple zones causes the total production rate and/or bottom-hole pressure (BHP) to fall below a target limit, then the constants A, B and C should be adjusted so that inflow is restricted without violating the global production constraints. A trial-and- error or model-based method may be used to achieve this.

The following section describes impact of water breakthrough in one or more inflow zones.

Water will eventually breakthrough at the well from one or more of the producing zones. The magnitude of the normalized SP signal reflects the mobile water saturation in the vicinity of the well, because the cross-coupling between the SP signal and the fluid potential gradient increases with increasing water saturation, as

illustrated in Figure 6.

Figure 6 shows two graphs that illustrate the

relative streaming potential coupling coefficient (C _t ) as a function of water saturation ( S _w ) during drainage and imbibition, measured in sandstone core plugs saturated with oil and water.

Figures 6 illustrates that the larger the relative coupling coefficient, the larger the streaming potential is for a given fluid potential. The relative coupling coefficient decreases with decreasing water saturation during drainage (oil displaces water) and increases with increasing water saturation during imbibition (water displaces oil) . Consequently, larger values of streaming potential are recorded at a well as the water saturation increases, both before and after water breakthrough.

It will be understood that regions of an underground formation with higher mobile water saturation have higher watercut. Inflow to the well in each inflow zone post- breakthrough can therefore be controlled using the algorithms described above, because SP signals which are larger in magnitude reflect a higher watercut. Zones may have a large SP signal either because the water is closer, or because the watercut is higher. The control response is the same in each case.

The method and system according to the invention are based on the insight that the value of Streaming

Potential (SP) measured in the well reflects the distance of the waterfront from the well. The higher the magnitude of the measured SP, the closer the waterfront. Therefore variations in the magnitude of the measured SP along the wellbore are indicative of uneven encroachment of water on the wellbore.

It will be understood that the term substantially uniform migration of a waterfront through a formation to an inflow region of a well as used in this specification and claims means that the lack of uniformity of the approach of a waterfront towards a well inflow region as illustrated by the peaks in Figures 2-4 may be decreased in a range from only a few percent to hundred percent.

It will further be understood that the method and system according to the present invention may incorporate these and other embodiments, which use measurements of Streaming Potential (SP) , acquired using electrodes installed downhole in a well, to detect changes in water saturation at a distance from the well. The measurements may be used in a feedback loop to directly actuate one or more Inflow Control Valves (ICVs) and/or other Inflow

Control Devices ( ICDs ) installed downhole. This will improve oil and gas recovery from the well and delays water production by controlling inflow such that the encroaching water reaches the well evenly and at the same time.